Directional drilling involves controlling the direction of a borehole as it is being drilled. Since boreholes are drilled in three dimensional space, the direction of a borehole includes both its inclination relative to vertical as well as its azimuth. Usually the goal of directional drilling is to reach a target subterranean destination with the drilling string, typically a potential hydrocarbon producing formation.
Directional drilling typically requires the use of a bottom hole assembly (BHA) at or near the end of the drilling string which incorporates drilling tools for controlling the drilling direction. Such tools may typically include one or more drilling motors and/or one or more rotary steerable tools.
In order to optimize the drilling operation and wellbore placement, it is often desirable to be provided with information concerning the environmental conditions of the surrounding formation being drilled and information concerning the operational and directional parameters of the drilling string, including the bottom hole assembly. For example, it is often necessary to adjust the direction of the borehole frequently while directional drilling, either to accommodate a planned change in direction or to compensate for unintended and unwanted deflection of the borehole.
In addition, it is often desirable that the information concerning the environmental, directional and operational parameters of the drilling operation be provided to the operator on a reasonably current (i.e., “real time”) basis. The ability to obtain real time information while drilling potentially facilitates a relatively more economical and more efficient drilling operation.
For example, the performance of a bottom hole assembly, and in particular the performance and life of a downhole motor, may be optimized by the real time transmission of the temperature of the bearings of the motor or the rotations per minute of the drive shaft of the motor. Similarly, the drilling operation itself may be optimized by the real time transmission of information relating to environmental or borehole conditions, such as measurements of natural gamma rays, borehole inclination, borehole pressure, resistivity of the formation and weight on bit. Real time transmission of this information permits real time adjustments in the operating parameters of the bottom hole assembly and real time adjustments to the drilling operation itself.
Accordingly, borehole telemetry systems have been developed which enable the gathering of relevant information downhole and the transmission of the information to the surface on a real time basis.
For example, mud pulse telemetry systems transmit signals to the surface through the drilling mud in the drilling string, which signals may include information gathered from one or more downhole sensors. More particularly, pressure signals, modulated with information from the downhole sensors, can be transmitted from downhole and can be received and demodulated at the surface. The downhole sensors may include various sensors such as gamma ray, resistivity, porosity or temperature sensors for measuring formation characteristics or other downhole parameters. In addition, the downhole sensors may include one or more magnetometers, accelerometers or other sensors for measuring the direction or inclination of the borehole, weight-on-bit or other drilling parameters.
Mud pulse telemetry systems are typically located above the bottom hole assembly. For example, when used with a downhole motor, a mud pulse telemetry system is typically located above the motor so that it is spaced a substantial distance from the drill bit. One reason for this is that it may be difficult if not impossible to pass mud pulses through the downhole motor or through the other components of the downhole motor drilling assembly without incurring significant interference or noise.
In addition, the downhole sensors associated with the mud pulse telemetry system are often similarly located above the bottom hole assembly, again due to the difficulty in transmitting the information from the sensors through the bottom hole assembly.
As a result, environmental information obtained from the downhole sensors may not necessary correlate with the actual conditions at or adjacent to the drill bit. Rather, the sensors are providing information relating to conditions which are substantially spaced from the drill bit. For example, a conventional mud pulse telemetry system and associated downhole sensors may have a depth lag relative to the drill bit of up to or greater than 60 feet (18.28 meters).
Because of this depth lag, it is possible to drill out of a hydrocarbon producing formation before detecting the exit, resulting in the need to drill several meters of borehole to get back into the pay zone. The interval drilled outside of the pay zone results in costly lost production over that interval over the life of the well. In some cases this may represent millions of dollars in lost production revenue to the operator, not to mention the wasted cost of putting completion equipment over the non-producing interval to reach producing zones further down in the well.
Other difficulties arise with the depth lag between the downhole sensors and the drill bit in deciding when it is appropriate to stop drilling and run casing in the borehole, which decision is often driven by formation characteristics. For example, it is often desirable to set a casing section in or before certain formations to avoid further drilling or production problems after completion of the borehole.
To overcome this undesirable depth lag, “near bit” sensors have been developed which are designed to be placed adjacent to or near the drill bit. Near bit sensors provide early detection of changes to the formation while drilling, minimizing the need for lengthy corrective drilling intervals and service costs. The drilling operation, including the trajectory of the drill bit, may then be adjusted in response to the sensed information, which information is more closely indicative of the actual conditions existing at the drill bit than if the sensors are located above the bottom hole assembly.
In order to use near bit sensors, a system or method must typically be provided for transmitting information from the downhole sensors either to a telemetry system located above the bottom hole assembly or directly to the surface. A system or method may also be required for conveying the required electrical power to the downhole sensors from the surface or from some other power source located downhole. Various attempts have been made to provide a system or method for transmitting information and/or power directly or indirectly between a location at or below a bottom hole assembly and a location above the bottom hole assembly.
As one example, acoustic and seismic telemetry systems have been developed for the transmission of acoustic or seismic signals or waves through the drilling string or surrounding formation. The acoustic or seismic signals are generated by a downhole acoustic or seismic generator. However, a relatively large amount of power is typically required in order to generate a signal of sufficient magnitude that the signal is detectable at the surface. As a result, a large amount of electrical power must be supplied downhole or repeater transceivers must be used at intervals along the drilling string to boost the signal as it propagates along the drilling string toward the surface.
U.S. Pat. No. 5,163,521 issued Nov. 17, 1992 to Pustanyk et. al., U.S. Pat. No. 5,410,303 issued Apr. 25, 1995 to Comeau et. al., and U.S. Pat. No. 5,602,541 issued Feb. 11, 1997 to Comeau et. al. all describe a telemetry tool, a downhole motor having a bearing assembly, and a drill bit. A sensor and a transmitter are provided in a sealed cavity within the housing of the downhole motor adjacent the drill bit. A signal from the sensor is transmitted by the transmitter to a receiver in the telemetry tool, which telemetry tool then transmits the information to the surface. The signals are transmitted from the transmitter to the receiver by a wireless system. Specifically, the information is transmitted by frequency modulated acoustic signals indicative of the sensed information. Preferably, the transmitted signals are acoustic signals having a frequency in the range below 5000 Hz.
As a second example, electromagnetic telemetry systems have been developed which rely upon the transmission of electromagnetic signals through the formation surrounding the drilling string. There are two different types of electromagnetic telemetry systems which are typically used downhole.
In a first type of electromagnetic telemetry system, a toroid is positioned within the drilling string for generation of an electromagnetic wave through the formation. Specifically, a primary winding, carrying the sensed information, is wrapped around the toroid and a secondary winding is formed by the drilling string. A receiver for detecting the electromagnetic waves may be connected to the ground at the surface or may be associated with a telemetry system or a repeater transceiver located at a position uphole from the transmitter. In this first type of electromagnetic telemetry system, the outer sheath of the drilling string must protect the windings of the toroid while continuing to provide structural integrity to the drilling string. This requirement presents design challenges due to the relatively high stresses to which the drilling string is typically exposed during drilling operations.
In a second type of electromagnetic telemetry system, an electrical discontinuity is created in the drilling string. The electrical discontinuity typically comprises an insulative gap or insulated zone in the drilling string. Such an electromagnetic telemetry system is described in U.S. Pat. No. 4,691,203 issued Sep. 1, 1987 to Rubin et al. The insulative gap may be provided by an insulating material comprising a substantial area of the outer sheath or surface of the drilling string. The insulating material may extend for several inches or several feet along the drilling string. The presence of this insulative gap of insulating material may interfere with the structural integrity of the drilling string and may also be susceptible to damage during drilling operations.
As with acoustic and seismic telemetry systems, electromagnetic telemetry systems also typically require a relatively large amount of electrical power, due to attenuation of the electromagnetic signals as they travel toward the surface. Attenuation of the electromagnetic signals as they are propagated through the formation is directly related to the distance over which the signals must be transmitted, the data transmission rate and the electrical resistivity of the formation. The conductivity and the heterogeneity of the surrounding formation may particularly adversely affect the propagation of the electromagnetic radiation through the formation. As a result, electrical power must be supplied downhole or repeater transceivers must be used at intervals along the drilling string to boost the signal as it propagates along the drilling string toward the surface.
Various attempts have been made in the prior art to address the difficulties or disadvantages associated with electromagnetic telemetry systems. However, none of these attempts have provided a fully satisfactory solution as each continues to require the propagation of an electromagnetic signal through the formation. Examples include: U.S. Pat. No. 4,496,174 issued Jan. 29, 1985 to McDonald et. al.; U.S. Pat. No. 4,725,837 issued Feb. 16, 1988 to Rubin; U.S. Pat. No. 4,691,203 issued Sep. 1, 1987 to Rubin et. al.; U.S. Pat. No. 5,160,925 issued Nov. 3, 1992 to Dailey et. al.; PCT International Application PCT/US92/03183 published Oct. 29, 1992 as WO 92/18882; U.S. Pat. No. 5,359,324 issued Oct. 25, 1994 to Clark et. al. and European Patent Specification EP 0 540 425 B1 published Sep. 25, 1996.
U.S. Pat. No. 6,392,561 issued May 21, 2002 to Davies et. al. describes a telemetry system for transmitting electrical signals embodying information from downhole sensors through portions of a downhole motor using components of the motor as a conducting path. This telemetry system relies upon inductive coupling between the transceivers and the conducting path and upon a slip ring mechanism for transmitting the electrical signals between rotating and non-rotating components of the motor within the conducting path.
U.S. Patent Application Publication No. US 2004/0119607 A1 by Davies et al describes a telemetry system and method for communicating information axially along a drilling string using components of the drilling string as a conducting path. This telemetry system relies upon inductive coupling between the transceivers and the conducting path and upon a slip ring mechanism for transmitting the electrical signals between rotating and non-rotating components of a motor contained within the drilling string.
U.S. Pat. No. 5,725,061 issued Mar. 10, 1998 to Van Steenwyk et al describes a downhole drill bit drive motor assembly which provides a bilateral low resistance path from the upper end of the motor to the lower end of the motor by employing an insulated wire or a group of several wires through the rotor of the motor. Fixed electrical contacts are provided at the upper end of the motor to provide a connection to a wireline. Rotary electrical contacts which provide continuous electrical contact as a rotary portion rotates relative to a stationary portion are provided at the upper end, the lower end or at both ends of the rotor. An electrical conductor extends through the interior of the rotor, a coupling and an output shaft to the bit box on the end of the output shaft. The rotary electrical contact is comprised of an electrical swivel assembly providing direct electrical contact between related rotating conducting parts or a rotary transformer apparatus for the transmission of alternating current power and signal data by magnetic coupling means.
There remains a need for a downhole drilling motor which provides a conducting path substantially therethrough which facilitates the transmission of power and/or communication signals through the drilling motor.
There is also a need for a downhole drilling motor which can be incorporated into a telemetry system for transmitting power and/or communication signals between locations above and below the drilling motor.
There is also a need for a downhole drilling motor which includes an assimilating connector for conductively connecting conductors of a conducting path extending through the motor which are capable of a movement relative to each other.
There is also a need for an assimilating connector for conductively connecting a first conductor and a second conductor which are capable of a movement relative to each other.